Deductions from Royalties

Historically, the oil and gas industry has treated the deductions from freehold royalties on oil and gas differently. Freehold oil royalties have been paid based on the price received for the oil at the outlet of an oil tank on or in the vicinity of the freeholder’s lands, without deducting costs such as separation, water disposal and oil storage incurred by the oil company-lessee between the point of production at the well head and the point of sale at the tank outlet. Freehold gas royalties have been paid based on the price received for the gas and gas by-products at the point of sale after deducting all of the costs incurred by the oil company-lessee between the point of production and the point of sale.

To a large extent, these different methods of arriving at the value on which to pay freehold oil and gas royalties reflect the position which the Government of Alberta has historically adopted with respect to allowable deductions from Crown oil and gas royalties.

In the years following the 1947 Leduc discovery, increased oil exploration resulted in the discovery of significant volumes of natural gas in western Canada. Unlike oil, gas can not be stored at the wellhead and to be sold must be delivered by a pipeline to an end user. Typically, the gas is processed to remove impurities and valuable natural gas liquids prior to pipelining. In the 1950's no gas plant or pipeline infrastructure was in place to get new found gas to market and, to encourage the oil and gas industry to develop expensive gas gathering and processing facilities in Alberta, the government of former premier Earnest Manning supported the implementation of the ‘Jumping Pound Formula’. This formula forms the basis for what has come to be known as the gas cost allowance (“GCA”) system.

Under GCA, a company producing gas from Crown lands in Alberta is allowed to deduct certain gas gathering and processing costs in calculating the royalties due to the Province. Deductible costs include:

all costs to operate the gas gathering and processing facilities during the year (actual costs plus 10% in deemed overhead);

capital cost allowance - depreciation at the rate of 1/20th of the cost of all equipment used to make the gas ‘market-ready’, including compressors, gathering pipelines, plant equipment, etc., chargeable annually over a period of 20 years;

return on capital invested - an annual return of 15% of the average capital invested in facilities during that year.

The vast majority of major gas pools discovered during the 1950's, 60's and 70's were ‘unitized’ before being brought on production. In a unit agreement, the interests of all oil company-lessees and all owner-lessors (both the Crown and freehold owners) in a particular subsurface oil or gas pool are combined for purposes of more efficient development of the pool reserves. Unit agreements in which gas is unitized almost invariably include clauses amending the royalty clause in the lease agreements of all involved freeholders to permit their oil company-lessees (the unit working interest owners) to deduct “proper” costs incurred in gathering and processing the unitized substances, including a “reasonable” return on investment.

In most of the gas units formed prior to the mid-1980's, the companies who were the unit working interest owners built both the gas gathering system and the gas plant required to process the gas produced from the unit. Typically, the Crown was the predominant royalty owner in the unit agreement. Because the unit working interest owners calculated the Crown’s royalty share of unit production based on the GCA system, it was simple and logical for these companies to determine the ‘proper’ costs and the ‘reasonable’ return on investment for gathering and processing their freehold owners’ royalty share of unit production based on the costs and rate of return allowed by the Crown under GCA.

A freeholder typically owns only a single tract of minerals and doesn’t have the same incentive as the Alberta Government does to provide oil company-lessees with generous GCA deductions to encourage province-wide gas facility infrastructure. Perhaps if freeholders understood the GCA calculation, widespread objections to its application to their unit royalties would have been raised. But few freeholders understand GCA. Furthermore, gas prices increased 40-fold between the early 1950's and the mid-1980's. These rising gas prices masked the impact of GCA on freeholder gas unit royalties. Presumably because of the lack of opposition from freehold owners and because it was simpler to apply the same system of deductions to both Crown and freehold royalties, the oil and gas industry gradually extended the GCA system to the calculation of freehold gas royalties in non-unitized situations where the freeholder had reserved a ‘gross’ royalty on gas ‘produced and marketed’.

In the mid-1980's, Canadian natural gas markets were de-regulated. The average price of gas sold in Alberta, which had peaked at $104 per 1000 m3 ($2.92/Mcf) in 1984, fell to less than half this value over the next 7 years. Concurrently, oil prices collapsed.

Most of Alberta’s gas gathering and processing infrastructure had been in place for more than 20 years by the late 1980's. It might have been expected that the capital cost allowance and return on invested capital components of GCA would have declined resulting in substantially lower gas gathering and processing costs throughout the Province. Instead, an entire new ‘industry’ sprang up as clever financiers structured limited partnerships and ‘mid-stream’ companies to purchase fully-depreciated gas gathering and processing facilities from the original facility owners. This had the effect of increasing the capital investment on which the depreciation and the return on average invested capital components of GCA was based. Any gas owned by the new facility owners and processed through their newly-purchased facilities became eligible for higher GCA deductions. The new facility owners also charged ‘custom processing fees’ to gather and process other companies’ gas. Instead of declining as would have been expected, the cost to gather and process gas increased substantially.

In 1988, the CAPL lease was introduced for use in western Canada. The CAPL 88 lease makes no reference to ‘gross’ royalties and requires the freehold owner-lessor to “bear its reasonable proportion of any expense incurred by the lessee for separating, treating, processing and transportation to the point of sale beyond the point of measurement”. In a number of situations the “expense incurred by the lessee” somehow exceeded the value of the gas sold and freeholders received invoices rather than royalty checks from their lessees.

In 1989, Alberta’s Energy Minister wrote to the principal oil and gas industry associations expressing concern that “excessive gas processing charges” were undermining “freehold and crown royalties” and advising that in some situations: freehold owners not only have received no royalty, they have actually been billed for processing costs”. The Minister suggested that the industry develop a “system of peer arbitrartion” which would resolve the problem without requiring regulatory intervention1.

In response, the oil and gas industry associations formed a task force which developed a set of guidelines known as Jumping Pound 90 or JP-90 for use in calculating custom processing fees. These guidelines recommend that a before tax rate of return on average invested capital (which includes a 10% overhead allowance) of between 20% and 23% be applied by new facility owners to determine custom processing fees. Can you earn 23% on your invested capital? Even if these guidelines were fair to freeholders, which in FHOA’s view they are not, nothing requires an oil company-lessee to follow the guidelines. Contrary to the Minister’s suggestion, the task force did not establish any system of peer arbitration to ensure compliance with these guidelines. It concluded that “communication and subsequent negotiation will eliminate the majority of complaints”.2

The CAPL 91 lease introduced a negotiable cap on the expenses which may be deducted from royalties by providing that the royalty “shall not be less than ___ percent (___%) of the royalty that would have been payable to the lessor if no such expenses had been incurred by the lessee ...”. The introduction of this cap was clearly intended to improve the position of the freehold owner-lessor and can presumably be attributed to the Alberta Government’s involvement.

To the extent that the generous deductions provided to the oil and gas industry by the Crown under GCA have contributed to increased gas prices which benefit freehold owners as well as the Crown, it is perhaps fair and reasonable that GCA should also apply to freehold royalties. But the Crown has rules and regulations which govern what an oil company can include in the operating and capital cost components of GCA and what rate of return on investment can be charged. The Crown also has knowledgeable experts who regularly audit the records of companies to ensure compliance with the Crown’s rules. In the case of deductions from freehold gas royalties, there are guidelines but they are not enforced - in effect there are no rules.

For instance, in situations where a fully-depreciated gas processing facility has been sold for an inflated price to a ‘mid-streamer’ who then charges the former facility owners excessive custom processing fees based on the increased capital base of the facility, Crown auditors may disallow a portion of the custom processing fee claimed by the former facility owners against their Crown royalties. Freehold owners have no access to the information necessary to even recognize that they are being subjected to this type of skulduggery.

The royalty clause which governs the deductions from freehold royalties for both oil and gas in most pre-CAPL freehold leases is the same - the freeholder reserves a “gross royalty” of a certain per cent (typically 12½% - 18%) of “the leased substances produced and marketed” from his lands and the oil company-lessee commits to remit to the freeholder that per cent of the “current market value” ... “at the wellhead” or “on the lands” of all leased substances produced and marketed. Based on this common clause, the oil and gas industry has historically applied radically different methods to the calculation of deductions from freehold oil and gas royalties. In the case of oil, no deductions have been applied and the freeholder has typically received a ‘gross’ royalty on oil ‘produced and marketed’. In the case of gas, the industry has deducted everything including the ‘kitchen sink’ and a rate of return on its investment in the sink.

In 1998, a Court of Queen’s Bench of Alberta judge effectively resolved this obvious dichotomy by ignoring more than 50 years of industry practice with respect to deductions from oil royalties and finding that the above royalty provision in a freehold lease meant an oil company-lessee could deduct properly incurred costs to gather, treat and store oil prior to its sale3. According to the trial judge, ‘properly incurred costs’ should include the operating costs of all facilities downstream from the wellhead to the point of sale plus a rate of return on capital invested. This decision has the potential to substantially reduce or completely eliminate freehold oil royalties in circumstances such as those in which oil is produced from freehold lands at a high water/oil ratio. It also opens the door to the same type of abuse in the case of deductions from freehold oil royalties as has historically occurred with respect to freehold gas royalties (“Understanding Freehold Leases - The Acanthus Decision”).